Closed-Loop Geosteering Device and Method

ABSTRACT

A closed-loop method for geosteering a subterranean borehole includes rotating a roll-stabilized control unit in the borehole, obtaining formation evaluation sensor measurements via sensors located in the control unit, and processing downhole the sensor measurements to obtain a corrective steering tool setting that may be applied to a steering tool to control a direction of drilling. A logging while drilling method includes obtaining sensor measurements via sensors located on a rotating roll-stabilized control unit and processing the sensor measurements to obtain an LWD image. A downhole tool includes a downhole tool body and a roll-stabilized control unit. The roll-stabilized control unit is deployed in a through bore of the tool body such that it is free to rotate with respect to the tool body. A tool face sensor and a partially shielded gamma ray sensor are deployed in the roll-stabilized control unit.

RELATED APPLICATIONS

None.

FIELD OF THE INVENTION

The disclosed subject matter relates generally to an apparatus and method for geosteering a subterranean borehole. More particularly, the disclosed embodiments relate to an apparatus and method for a closed-loop geosteering operation.

BACKGROUND

The use of on-site and remote geosteering methods is well known in the downhole drilling arts. During such geosteering operations, drilling typically proceeds according to a predetermined well plan (e.g., derived using geometric considerations in combination with a three dimensional model of the subterranean formations). Real-time geological measurements, for example, measurement while drilling (MWD), logging while drilling (LWD), and/or mud logging measurements, are made while drilling. Data obtained from these measurements are then used to make “on the fly” adjustments to the direction of drilling, for example, to maintain the drill bit at a desired location in a payzone.

In conventional geosteering operations, steering decisions are made at the surface, e.g., at the rig site or at a remote location. LWD data (or other downhole data) are compressed downhole and then transmitted to the surface while drilling (e.g., via conventional telemetry techniques). The transmitted data is then processed at the surface in combination with a model of the subterranean formations to determine a subsequent drilling direction (or a correction to the current drilling direction). Changes to the predetermined (preplanned) drilling direction (e.g., in the form of a corrected well path) are then transmitted from the surface to a downhole steering tool (e.g., via conventional downlinking techniques).

While such geosteering methods are commercially utilized, there remains room for improvement. For example, the viability of prior art geosteering methods is often limited by the bandwidth and accuracy of the communication channel between the bottom hole assembly (BHA) and the surface. This limitation can cause geosteering methods to be slow and somewhat unresponsive (e.g., due to the time lag associated with transmitting LWD measurements to the surface and then transmitting steering instructions or a corrected well plan from the surface to the BHA). Moreover, telemetry errors and/or the reduced accuracy that results from data compression can lead to further errors when computing the corrected well path. These and other limitations of prior art techniques lead to a need for improved geosteering methods.

SUMMARY

A closed-loop method for geosteering a subterranean borehole is disclosed. A subterranean borehole is drilled using a bottom hole assembly including a steering tool having a roll-stabilized control unit. The roll stabilized control unit includes at least one formation evaluation sensor and a tool face sensor deployed therein. The roll-stabilized control unit may be rotated with respect to the borehole while drilling. Corresponding formation evaluation sensor measurements and tool face sensor measurements are obtained while rotating the roll-stabilized control unit and are processed to compute a borehole image parameter. The borehole image parameter is processed to obtain a corrective steering tool setting which is applied to the steering tool to change a direction of drilling. The method may be executed continuously while drilling so as implement closed-loop control of the direction of drilling.

A logging while drilling method includes deploying a logging while drilling tool in a subterranean borehole. The tool includes a roll-stabilized control unit deployed in a tool body, the roll stabilized control unit including at least one formation evaluation sensor and a tool face sensor deployed therein. The logging while drilling tool body is held rotationally stationary with respect to the borehole while the roll-stabilized control unit is rotated with respect to the borehole. Corresponding formation evaluation sensor measurements and tool face sensor measurements are obtained while rotating the roll-stabilized control unit. The sensor measurements are then processed to obtain a logging while drilling image.

A downhole tool includes a downhole tool body and a roll-stabilized control unit. The roll-stabilized control unit is deployed in a through bore of the tool body such that it is free to rotate with respect to the tool body. A tool face sensor and a partially shielded gamma ray sensor are deployed in the roll-stabilized control unit. The gamma ray sensor may include a scintillator crystal and a substantially cylindrical shield that subtends an angle less than 360 degrees. The downhole tool may include, for example, a rotary steerable drilling tool or a logging while drilling tool.

Disclosed embodiments may provide several technical advantages. For example, in providing a closed-loop methodology, the disclosed embodiments tends to advantageously improve the timeliness and accuracy of geosteering operations as well as further improve borehole placement in the subterranean geology (e.g., in a predetermined payzone) while also reducing borehole tortuosity. Deployment of logging while drilling sensors in a roll-stabilized control unit may advantageously enable borehole images to be obtained when the drill string is stationary (non-rotating) in the borehole or during slide drilling operation. Moreover, the deployment of LWD sensors in a roll stabilized unit may reduce image blurring owing to stick slip and torsional vibrations of the drill string.

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the disclosed subject matter, and the advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which:

FIG. 1 depicts an example drilling rig on which disclosed embodiments may be utilized.

FIG. 2 depicts a flow chart of one disclosed method embodiment.

FIG. 3 depicts a portion of a steering tool having a roll-stabilized control unit (in hidden lines) deployed in the throughbore of a drill collar.

FIGS. 4A and 4B (collectively FIG. 4) depict a first embodiment of an integrated gamma ray sensor deployed in the roll-stabilized control unit of FIG. 3 in cutaway perspective (FIG. 4A) and circular cross-sectional (FIG. 4B) views.

FIGS. 5A and 5B (collectively FIG. 5) depict a second embodiment of an integrated gamma ray sensor deployed in the roll-stabilized control unit of FIG. 3 in cutaway perspective (FIG. 5A) and circular cross-sectional (FIG. 5B) views.

FIGS. 6A and 6B (collectively FIG. 6) depict a third embodiment of an integrated gamma ray sensor deployed in the roll-stabilized control unit of FIG. 3 in cutaway perspective (FIG. 6A) and circular cross-sectional (FIG. 6B) views.

FIG. 7 depicts a flow chart of another disclosed method embodiment.

FIG. 8 depicts a hypothetical eight-sector gamma image in which the borehole crosses a formation of interest (an active bed).

FIG. 9 depicts a flow chart of yet another disclosed method embodiment.

FIG. 10 depicts a hypothetical eight-sector gamma image in which an active bed drops down away from the borehole.

DETAILED DESCRIPTION

FIG. 1 depicts a drilling rig 10 suitable for using various method and system embodiments disclosed herein. A semisubmersible drilling platform 12 is positioned over an oil or gas formation (not shown) disposed below the sea floor 16. A subsea conduit 18 extends from deck 20 of platform 12 to a wellhead installation 22. The platform may include a derrick and a hoisting apparatus for raising and lowering a drill string 30, which, as shown, extends into borehole 40 and includes a bottom hole assembly (BHA) 50. The BHA 50 includes a drill bit 32 and a steering tool 60 including a roll-stabilized control unit (not shown on FIG. 1). The roll-stabilized control unit further includes at least one formation evaluation (FE) sensor (e.g., an azimuthal gamma sensor) and a tool face sensor. These sensors are depicted schematically in FIGS. 1 at 62 and 64. The BHA 50 may further include substantially any other suitable downhole tools such as a downhole drilling motor, a downhole telemetry system, a reaming tool, and the like. The disclosed embodiments are not limited in these regards.

It will be understood that substantially any suitable steering tool 60 having a roll stabilized control unit (e.g., a roll-stabilized sensor housing) may be used. For example, certain of the PowerDrive® rotary steerable systems (available from Schlumberger) make use of a roll stabilized control unit. The PowerDrive® Archer® makes use of an internal roll-stabilized control unit as well as a lower steering section joined at a swivel with an upper section. The swivel is actively tilted via pistons so as to change the angle of the lower section with respect to the upper section and maintain a desired drilling direction as the bottom hole assembly rotates in the borehole. Accelerometer, magnetometer, and rate gyro sensor sets may be deployed in the roll-stabilized control unit such that they remain substantially stationary (in a bias phase) or rotate slowly with respect to the borehole (in a neutral phase). To drill a desired curvature, the bias phase and neutral phase may be alternated during drilling at a predetermined ratio (referred to as the steering ratio).

It will be understood by those of ordinary skill in the art that the deployment depicted on FIG. 1 is merely an example for the purposes of describing the disclosed embodiments set forth herein. It will be further understood that the disclosed embodiments are not limited to use with a semisubmersible platform 12 as illustrated on FIG. 1. These embodiments are equally well suited for use with any kind of subterranean drilling operation, either offshore or onshore.

FIG. 2 depicts a flow chart of one closed-loop method embodiment 100 for controlling the direction of drilling a subterranean borehole. A subterranean borehole is drilled at 102, for example, via rotating a drill string, pumping drilling fluid through a downhole mud motor, and/or the like. The drill string includes a steering tool including a roll-stabilized control unit including at least one formation evaluation (FE) sensor. While drilling at 102 the steering tool may be actuated so as to control the direction of drilling. The roll-stabilized control unit is rotated with respect to the borehole at 104 thereby causing the FE sensor to also rotate with respect to the borehole. At 106 FE measurements are made using the FE sensor while rotating in 104. The FE measurements may include, for example, a plurality of gamma ray measurements and corresponding tool face measurements. The FE measurements may be processed downhole at 108 (e.g., using a downhole processor located in the steering tool or elsewhere in the drill string) to obtain a borehole image parameter that may be further processed downhole to obtain a corrective steering tool setting at 110. The steering tool setting may then be applied to the steering tool at 112 to control the direction of drilling (e.g., to control/change the borehole inclination). Steps 106, 108, 110, and 112 may be continuously repeated downhole so as to maintain a desired drilling direction (e.g. a fixed distance above or below a formation boundary).

FIG. 3 depicts a portion of a downhole tool 200 (e.g., a steering tool or a logging while drilling tool) having a roll-stabilized control unit 210 (in hidden lines) deployed in the through bore 232 of a drill collar 230. In use the drill collar 230 is coupled with a drill string and rotates at the collar rotation speed or the bit rotation speed depending upon whether it is deployed above or below a mud motor. The roll-stabilized control unit 210 may be configured to rotate with respect to the drill collar 230 such that it may be substantially geostationary (nonrotating with respect to the borehole) or rotated at some predetermined angular velocity with respect to the borehole. For example, the roll-stabilized control unit 210 may be configured to rotate at some absolute rotation rate with respect to the borehole (in the earth's reference frame) in the neutral phase. Alternatively, the roll-stabilized control unit may be configured to rotate at some relative rotation rate with respect to the collar rotation rate (such as a fixed number of revolutions per minute less than the collar rotation rate). In such embodiments, azimuthally resolved FE measurements may be obtained while in the neutral phase (i.e., when the roll-stabilized control unit rotates with respect to the borehole).

It will be understood that the disclosed embodiments are not limited to steering tool embodiments having a roll-stabilized unit. The disclosed embodiments may also include a roll-stabilized unit deployed in a measurement while drilling (MWD) or logging while drilling (LWD) tool with the MWD and/or LWD sensors deployed in the roll-stabilized unit. Such an MWD and/or LWD tool may be utilized, for example, to obtain azimuthally resolved sensor data and/or LWD images. Moreover, a downhole steering tool connected via a common communication bus in the BHA may control the steering direction based on the azimuthal FE image constructed at the roll-stabilized MWD/LWD unit.

Deployment of MWD and/or LWD sensors in a roll-stabilized unit may advantageously enable borehole imaging data to be obtained when the drill string is not rotating (e.g., when the drill bit is off bottom and circulating drilling fluid or when drilling in sliding mode). For example, various downhole sensors may be utilized to determine the current state of the drill string/bit. These sensors may include, for example, weight on bit sensors, accelerometers, and the like. U.S. Patent Publication 2013/0341091, which is fully incorporated by reference herein, discloses downhole methods for processing sensor data to determining whether or not the drill string is rotating and on or off bottom. In certain embodiments disclosed herein the roll-stabilized control unit may be programmed to rotate when the drill string is not rotating and the FE sensors may be programmed to obtain sensor data to obtain LWD images. Such embodiments may advantageously be utilized to produce LWD images without rotating the drill string, for example, in slide drilling applications, coiled tubing steering operations, when the drill bit is off bottom, and/or when the LWD tool is located above a mud motor. Deployment of the LWD sensors in a roll-stabilized control unit may further reduce image blurring and smearing owing to stick slip and torsional vibrations of the drill string. Moreover such embodiments may enable LWD imaging tools to be located further up the drill string so as to preserve valuable real-estate close to the bit

Suitable roll-stabilized housings are disclosed, for example, in U.S. Pat. Nos. 5,265,682 and 6,816,788, and GB 2,426,265. U.S. Pat. No. 5,265,682 discloses an apparatus in which impellers and mud flow are used to stabilize the housing. U.S. Pat. No. 6,816,788 uses an electrical motor to stabilize the housing. Notwithstanding, the disclosed embodiments are not limited to any particular drive mechanism for controlling the roll-stabilized unit.

In the disclosed embodiments, the steering tool 200 further includes an FE sensor deployed in the roll-stabilized unit 210. The FE sensor may include, for example, an integrated gamma ray sensor capable of providing real-time azimuthal gamma ray data while drilling. FIGS. 4-6 depict three embodiments in which a roll-stabilized unit includes an integrated gamma ray sensor. The roll-stabilized unit 210 typically further includes a tool face sensor deployed therein (e.g., including an accelerometer set).

FIGS. 4A and 4B depict a first embodiment of an integrated gamma ray sensor 220 deployed in the roll-stabilized control unit of FIG. 3. Sensor 220 includes a substantially cylindrical scintillator rod 222 deployed in a semi-cylindrical shield 224 in the roll-stabilized control unit 210. In the depicted embodiment, the scintillator rod 222 and the shield 224 are substantially co-axial. The shield 224 may be fabricated from substantially any suitable high density material such as tungsten. The semi-cylindrical shield provides a 180-degree azimuthal window 226 in which gamma rays may be detected in the formation.

FIGS. 5A and 5B depict a second embodiment of an integrated gamma ray sensor 240 deployed in the roll-stabilized control unit of FIG. 3. Sensor 240 includes a substantially cylindrical scintillator rod 242 axially offset in a substantially cylindrical shield 244 in the roll-stabilized control unit 210. As with sensor 220, the shield 244 may be fabricated from substantially any suitable high density material such as tungsten. Radially offsetting the scintillator rod 242 in the shield 244 tends to provide a narrower azimuthal window in which gamma rays may be detected in the formation (e.g., about 45-90 degrees in the depicted embodiment) and may therefore provide improved azimuthal resolution.

FIGS. 6A and 6B depict a third embodiment of an integrated gamma ray sensor 250 deployed in the roll-stabilized control unit of FIG. 3. Sensor 250 includes a substantially cylindrical scintillator rod 252 deployed in the roll-stabilized control unit 210. In the depicted embodiment, a partially cylindrical shield 254 is deployed on an inner surface of the drill collar 230 and rotates with the drill collar 230 such that the shield 254 and window 255 rotate with respect to the control unit 210. Again, the shield 254 may be fabricated from substantially any suitable high density material such as tungsten. The partially cylindrical shield provides an azimuthal window (e.g., 90 degree) in which gamma rays may be detected in the formation.

It will be understood that each of the embodiments disclosed on FIGS. 4-6 may be used to detect natural gamma rays or induced gamma rays. Those of ordinary skill in the art will readily appreciate that induced gamma rays may be used when making formation density and/or porosity logging measurements. In order to induce gamma rays the steering tool may further include a radioactive source deployed, for example, in the roll-stabilized control unit 210 or the drill collar 230.

It will be further understood that the steering tool embodiments depicted on FIGS. 4-6 may be utilized in the closed-loop geosteering method 100. For example, in the embodiments depicted on FIGS. 4 and 5, rotation of the roll-stabilized unit 210 with respect to the borehole enables azimuthally resolved gamma ray data to be acquired at 106. In the embodiment depicted on FIG. 6, rotation of the drill collar 230 with respect to the roll-stabilized unit 210 enables azimuthally resolved gamma ray data to be acquired at 106 (as the shield rotates about the housing). Using the embodiments depicted on FIGS. 4 and 5, logging while drilling images may be acquired while the steering tool is in the neutral phase (and the control unit is rotating with respect to the borehole). Using the embodiments depicted on FIG. 6, logging while drilling images may be acquired while the steering tool is in the bias phase (and in the neutral phase so long there is relative rotation between the collar 230 and the control unit 210 in the neutral phase).

The FE measurements may be acquired and correlated with corresponding tool face measurements while drilling. The measurements may then be distributed in azimuth (tool face) using substantially any known methodologies, for example, conventional binning, windowing, or probability distribution algorithms. U.S. Pat. No. 5,473,158 discloses a conventional binning algorithm. U.S. Pat. No. 7,027,926 discloses a technique for constructing a borehole image in which sensor data is convolved with a one-dimensional window function. U.S. Pat. No. 7,558,675 discloses an image constructing technique in which sensor data is probabilistically distributed in either one or two dimensions. Each of these patents (the '158, '926, and '675 patents) is incorporated by reference in its entirety herein.

With reference again to FIG. 2, the FE measurements may be processed downhole at 108 to obtain a borehole image parameter that may be evaluated downhole at 110 to control the direction of drilling. For example, the borehole image parameter may be compared with a predetermined value to obtain an error value which is in turn further processed downhole to obtain a corrective steering tool setting. Application of the corrective steering tool setting thus changes the direction of drilling. In one common geosteering operation, the intent is to drill a borehole a substantially fixed distance above or below a particular subterranean formation. For example, the borehole may be routed through an approximately horizontal oil-bearing reservoir (e.g., having an inclination in the range from about 80 to about 100 degrees). In such operations, the corrective steering tool setting is intended to build (increase) inclination, maintain the current inclination, or drop (decrease) inclination in response to the FE sensor measurements.

FIG. 7 depicts a flow chart of another closed-loop method embodiment 120 for controlling the direction of drilling a subterranean borehole. Method 120 is similar to method 100 in that a subterranean borehole is drilled at 102, for example, via rotating a drill string, pumping drilling fluid through a downhole mud motor, or the like. As with method 100, the drill string includes a steering tool including a roll-stabilized control unit including at least one formation evaluation (FE) sensor. The roll-stabilized control unit is rotated with respect to the borehole at 104 thereby causing the FE sensor to also rotate with respect to the borehole. At 106 FE measurements are made using the FE sensor while rotating in 104. The FE measurements may be processed downhole at 108 to obtain a borehole image parameter which may be further processed downhole at 122 to obtain a first corrective steering tool setting operative to change the borehole inclination (i.e., to build, drop, or hold inclination).

Method 120 further includes measuring the borehole azimuth at 124, e.g., using survey sensors such as accelerometers, magnetometers, and/or gyroscopic sensors deployed in the steering tool or elsewhere in the drill string. The measured borehole azimuth may be processed downhole at 126 to obtain a second corrective steering tool setting intended to control the borehole azimuth (i.e., to turn left or turn right). The measured azimuth may be processed, for example, in combination with a desired azimuth to obtain an azimuth error, which may be further processed downhole to obtain the second corrective steering tool setting. The first and second corrective steering tool settings may then be applied to the steering tool 128 to control the direction of drilling. It will be understood that the first and second corrective steering tool settings may be applied simultaneously (to change the inclination and azimuth simultaneously) or incrementally (so as to first change one and then the other of the inclination and azimuth). Steps 106, 108, 122, 124, 126, and 128 may be continuously repeated downhole so as to maintain a desired drilling direction (e.g. a fixed distance above or below a formation boundary).

Substantially any suitable borehole image parameter may be utilized in methods 100 and 120 (FIGS. 2 and 7). For example, the borehole image parameter may include (i) a difference or a ratio between high side gamma ray counts and low side gamma ray counts, (ii) a relative dip angle between the borehole and a formation (or formation boundary) of interest, and (iii) the azimuthal width and the intensity of a gamma ray peak or trough. The difference or ratio between high side gamma ray counts and low side gamma ray counts and the azimuthal width of a gamma ray peak or trough may be indicative of the distance between the borehole and a target formation while the relative dip angle between the borehole and a formation of interest is indicative of the relative direction of the borehole with respect to the formation of interest.

Using one of the gamma ray sensors depicted on FIGS. 4-6, the difference or ratio between high side and low side gamma ray counts may be utilized to sense bed boundaries above or below the tool. When the difference or ratio is outside a predetermined range of values (e.g., indicative of an approaching bed boundary), the direction of drilling may be appropriately changed so as to stay in the desired formation. For example, a ratio of high side to low side gamma ray counts above a first predetermined threshold may be taken to be indicative of an approaching bed boundary above the steering tool. The corrective steering tool setting may thus be selected to change the direction of drilling downward (in the direction of decreasing inclination) when the count ratio is above the first threshold. Likewise, a ratio of high side to low side counts below a second predetermined threshold may be taken to be indicative of an approaching bed boundary below the steering tool. The corrective steering tool setting may thus be selected to change the direction of drilling upward (in the direction of increasing inclination) when the count ratio is below the second threshold. Alternatively, a ratio between the high side measurement and a non-azimuthal measurement (made for example via summing or averaging the FE sensor measurements over all tool face angles) and/or a ratio between the low side measurement and a non-azimuthal measurement may be used to determine the location of an approaching bed boundary.

The azimuthally resolved FE measurements may also be processed to obtain a formation dip angle. The formation dip angle represents the relative angle between the borehole and a formation (or formation boundary) of interest. FIG. 8 depicts a hypothetical eight-sector gamma image in which the borehole crosses a formation of interest (an active bed). A formation dip angle may be computed from the image data using techniques known to those of ordinary skill in the art. The formation dip angle may then be further processed to obtain the corrective steering tool setting.

FIG. 9 depicts a flow chart of yet another method embodiment 140 for controlling the direction of drilling a subterranean borehole. Method 140 is similar to method 100 in that a subterranean borehole is drilled at 102, for example, via rotating a drill string, pumping drilling fluid through a downhole mud motor, or the like. As with method 100, the drill string includes a steering tool including a roll-stabilized control unit including at least one formation evaluation (FE) sensor. The roll-stabilized control unit is rotated with respect to the borehole at 104 thereby causing the FE sensor to also rotate with respect to the borehole. At 106 FE measurements are made using the FE sensor while rotating in 104. The rate of penetration (ROP) while drilling in 102 is received at 142. The ROP may be obtained, for example, from surface measurements via conventional downlinking techniques. Alternatively, the ROP may be computed downhole, for example, as disclosed in U.S. Pat. Nos. 7,058,512 and 7,916,041 and U.S. Patent Publication 2013/0341091 each of which is fully incorporated by reference herein. At 144 the ROP may be processed in combination with the FE measurements obtained at 106 to obtain a borehole image parameter such as a formation dip angle. The borehole image parameter may be further processed at 146 to obtain a corrective steering tool setting which may be applied to the steering tool at 148 to change the direction of drilling. Steps 106, 142, 144, 146, and 148 may be continuously repeated downhole so as to maintain a desired drilling direction (e.g. a fixed distance above or below a formation boundary).

FIG. 10 depicts a hypothetical eight-sector gamma image in which an active bed 302 drops down away from the borehole 304. Note that the width and intensity of the stripe (the band of high gamma counts) 306 decreases as the distance to the active formation increases (and conversely the width and intensity increases as the distance decreases). As such the azimuthal width and the intensity of the gamma data may be computed and processed to obtain the corrective steering tool parameter. For example, in an operation in which the borehole is intended to remain a fixed distance above an active formation, a reduced azimuthal width and intensity (as observed in FIG. 8) may be indicative of an increasing distance between the borehole and the active bed. The corrective steering tool setting may thus be selected to change the direction of drilling downward. Alternatively, an increased azimuthal width and intensity may be indicative of a decreasing distance between the borehole and the active bed. The corrective steering tool setting may thus be selected to change the direction of drilling upward.

It will be understood that the above described method embodiments may be advantageously operated in a closed-loop manner for both up/down (inclination) control and turn right/turn left (azimuth) control of the drilling operation. Such closed-loop operations enable the drilling direction to be controlled independently of any surface communications. However, the disclosed embodiments may also be executed as part of a cascaded loop control system. For example, a set point (target value) to the formation characteristics (e.g. Gamma counts) and/or azimuth may be downlinked from the surface on occasion. In such embodiments, a surface system may execute an outer loop automated control defined, for example, by a 3-D petro-physical model and/or defined by a 3-D well trajectory. Cascaded loop control systems are disclosed in U.S. Patent Publication 2010/0175922, which is fully incorporated by reference herein.

The methods described herein are configured for downhole implementation via one or more controllers/processors deployed downhole (e.g., in the steering tool). A suitable controller may include, for example, a programmable processor, such as a microprocessor or a microcontroller and processor-readable or computer-readable program code embodying logic, including FPGA (field-programmable gate array). A suitable processor may be utilized, for example, to execute the method embodiments described above with respect to FIGS. 2, 7, and 9. A suitable controller may also optionally include other controllable components, such as sensors (e.g., a depth sensor), data storage devices, power supplies, timers, and the like. The controller may also be disposed to be in electronic communication with the FE sensor and the tool face sensor (e.g., to receive corresponding sensor measurements). A typical controller may further optionally include volatile or non-volatile memory or a data storage device.

The controller may also optionally communicate with other instruments in the drill string, such as telemetry systems that communicate with the surface or an EM (electro-magnetic) short hop that enables two-way communication across a downhole motor. A surface controller may optionally run a closed loop control with a supervisory function, which communicates with a downhole closed-loop system to change the set point (target value) to the downhole control system. It will be appreciated that the controller is not necessarily located in the rotary steerable tool, but may be disposed elsewhere in the drill string in electronic communication therewith. Moreover, one skilled in the art will readily recognize that the multiple functions described above may be distributed among a number of electronic devices (controllers).

Moreover, it will be understood that the aspects and features of the disclosed embodiments may be embodied as logic that may be processed by, for example, by the above described controller. Similarly the logic may be embodied on software suitable to be executed by a processor, as is also well known in the art. The disclosed embodiments are not limited in this regard. The software, firmware, and/or processing device may be included, for example, in the downhole steering tool or elsewhere in the drill string. Electronic information such as logic, software, or measured or processed data may be stored in memory (volatile or non-volatile), or on conventional electronic data storage devices such as are well known in the art.

While the disclosed embodiments depict a steering tool having a roll-stabilized unit it will be understood that the disclosed embodiments are not limited only to steering tool embodiments. For example, the roll-stabilized unit may be deployed in an measurement while drilling (MWD) or logging while drilling (LWD) device. A downhole steering tool connected via a common communication bus in the BHA may control the steering direction based on the azimuthal FE image contructed at the roll-stabilized MWD/LWD unit.

Although a closed-loop geosteering device and method and advantages thereof have been described in detail, it should be understood that various changes, substitutions and alterations may be made herein without departing from the spirit and scope of the disclosure as defined by the appended claims. 

I claim:
 1. A closed-loop method for geosteering a subterranean borehole, the method comprising: (a) causing a bottom hole assembly to drill a subterranean borehole, the bottom hole assembly including a steering tool having a roll-stabilized control unit, the roll stabilized control unit including at least one formation evaluation sensor and a tool face sensor deployed therein; (b) causing the roll-stabilized unit to rotate with respect to the borehole while drilling in (a); (c) causing the formation evaluation sensor and the tool face sensor to obtain corresponding sensor measurements while rotating in (b); (d) processing the sensor measurements obtained in (c) to compute a borehole image parameter; (e) processing the borehole image parameter to obtain a corrective steering tool setting; and (f) applying the corrective steering tool setting to the steering tool to change a direction of drilling.
 2. The method of claim 1, further comprising: (g) continuously repeating (c), (d), (e), and (f) while drilling in (a).
 3. The method of claim 1, wherein the formation evaluation sensor comprises a gamma ray sensor deployed in the roll-stabilized control unit.
 4. The method of claim 3, wherein the gamma ray sensor comprises a substantially cylindrical scintillator deployed co-axially in a semi-cylindrical shield.
 5. The method of claim 3, wherein the gamma ray sensor comprises a substantially cylindrical scintillator deployed in a cylindrical shield, the scintillator being axially offset from the cylindrical shield.
 6. The method of claim 3, wherein the gamma ray sensor comprises a substantially cylindrical scintillator deployed in the roll-stabilized control unit and a partially cylindrical shield is deployed about the roll-stabilized control unit on an inner surface of a rotary steerable tool body.
 7. The method of claim 1, wherein the borehole image parameter is at least one of a difference or a ratio between high side gamma ray counts and low side gamma ray counts, a relative dip angle between the borehole and a formation boundary of interest, and an azimuthal width and intensity of a gamma ray peak or trough.
 8. The method of claim 1, wherein (d) further comprises processing the sensor measurements obtained in (c) and a rate of penetration in (a) to compute the borehole image parameter.
 9. The method of claim 1, wherein (e) further comprises processing the borehole image parameter and a borehole azimuth measurement to obtain the corrective steering tool setting.
 10. The method of claim 1, further comprising: (g) receiving a borehole azimuth measurement; (h) processing the borehole azimuth measurement to obtain a second corrective steering tool setting, the second steering tool setting operative to change a borehole azimuth; and (i) applying second corrective steering tool setting to the steering tool to change a direction of drilling.
 11. The method of claim 1, wherein (e) comprises processing the borehole image parameter in combination with a target image parameter to obtain a corrective steering tool setting.
 12. The method of claim 11, further comprising: (g) causing a surface system to execute an outer control loop to obtain the target image parameter; and (h) downlinking the target image parameter from the surface system to a downhole processor for processing in (e).
 13. A downhole tool comprising: a downhole tool body; a roll-stabilized control unit deployed in a through bore of the downhole tool body, the roll-stabilized control unit being free to rotate with respect to the downhole tool body; a tool face sensor deployed in the roll-stabilized control unit; and a partially shielded gamma ray sensor deployed in the roll-stabilized control unit, the gamma ray sensor including a scintillator crystal and a substantially cylindrical shield that subtends an angle less than 360 degrees.
 14. The downhole tool of claim 13, wherein the tool is a rotary steerable tool and the downhole tool body is a rotary steerable tool body;
 15. The downhole tool of claim 13, wherein the tool is a logging while drilling tool and the downhole tool body is a logging while drilling tool body;
 16. The downhole tool of claim 13, wherein the downhole tool body is configured to be connected with a drill string such that the tool body is rotationally coupled with the drill string.
 17. The downhole tool of claim 13, wherein the scintillator is substantially cylindrical and deployed co-axially in a semi-cylindrical shield with both the scintillator and the shield being deployed in the roll-stabilized control unit.
 18. The downhole tool of claim 13, wherein the scintillator is substantially cylindrical and deployed in a cylindrical shield, the scintillator being axially offset from the cylindrical shield with both the scintillator and the shield being deployed in the roll-stabilized control unit.
 19. The downhole tool of claim 13, wherein the scintillator is substantially cylindrical and deployed in the roll-stabilized control unit and the shield is partially cylindrical and deployed about the roll-stabilized control unit on an inner surface of a rotary steerable tool body.
 20. A logging while drilling method comprising: (a) deploying a logging while drilling tool in a subterranean borehole, the logging while drilling tool including a roll-stabilized control unit deployed in a tool body, the roll stabilized control unit including at least one formation evaluation sensor and a tool face sensor deployed therein; (b) causing the logging while drilling tool body to be rotationally stationary with respect to the borehole; (c) causing the roll-stabilized control unit to rotate with respect to the borehole; (d) causing the formation evaluation sensor and the tool face sensor to obtain corresponding sensor measurements while rotating in (c); (e) processing the corresponding formation evaluation sensor measurements and the tool face measurements obtained in (d) to obtain an image. 